1. Field of the Invention
The invention relates generally to improvements in drag bit cutter geometries and the attachment of such cutters to a bit blade.
2. Background Art
Oil wells and gas wells are typically created by a process of rotary drilling. In conventional rotary drilling a drill bit is mounted on the end of a drill string. At the surface a rotary drive turns the string, including the bit at the bottom of the hole, while a drilling fluid, or “mud,” is pumped through the drill string.
When the bit wears out or breaks during drilling, it must be brought up out of the hole in a process called “tripping-out.” During this process, a heavy hoist pulls the drillstring out of the hole and rig workers disconnect the components thereof in stages. Tripping-out of the borehole is a time-consuming endeavor. One trip can require days, and may significantly impact the drilling budget, as no drilling progress occurs during this period. To resume drilling the entire process must be reversed. Accordingly a bit's durability and drilling efficiency are very important, to minimize round trips for bit replacement during drilling, and to maximize drilling progress between trips.
The teeth of a drill bit crush or cut rock. One type of bit is a “drag” bit, where the entire bit rotates as a single unit. The body of the bit holds fixed teeth, or “cutters,” which are typically made of an extremely hard material, such as tungsten carbide, and are often coated with even harder substances, such as polycrystalline diamond compact (PDC). The body of the bit may be steel, or may be a matrix of a harder material such as tungsten carbide.
All drill bit teeth can be expected to fail eventually. Typically, PDC-type drill bit teeth have three common failure modes. The first failure mode involves inward abrasive wear of the cutting face in which a side of the cutter's hardened face is gradually eroded inward, so that a portion of the tooth's volume is gradually removed.
A second failure mode involves fracture of the cutting face or the cutting teeth. Because the force on the tooth's face is typically not evenly distributed, it is possible for failure in shear to occur (where part of the face, and possibly part of the body behind it, breaks away from the rest of the tooth). This is a particularly damaging failure mode, as the separated tooth fragment is likely to be encountered by remaining cutting teeth. Being much harder than the surrounding formation, the tooth fragment can fracture one or more other teeth. There is also a chance of a cascading effect where shards from one or more broken teeth cause further tooth breakage which continues to propagate to other teeth of the bit.
A final failure mode is a “prying out” failure, where all or most of a single tooth is removed from its retaining socket. With this type of failure, the single mass of hardened material has an even greater chance of damaging other teeth on the bit.
Accordingly, one approach to maximizing drilling efficiency is by increasing the durability and cutting efficiency of individual cutters, within the constraints of known cutter failure modes. Typically, this will involve balancing increased tooth clearance and exposure against increased susceptibility to the failure modes previously discussed.
Bent and bullet-type teeth represent two variations of such an approach. Angled or bent teeth, such as disclosed in U.S. Pat. No. 6,302,224, issued to Sherwood, hereby incorporated herein by reference, typically have two nonparallel axes. Often, bent drill bit teeth have a greater volume embedded in the bit body, and a lesser volume protruding therefrom. Such teeth can have a cutting face bent at an angle of up to 90 degrees relative to the shank. Although a greater volume of tooth embedded within the bit will reduce the likelihood of a prying out failure and results in an increased clearance, the bent tooth design is susceptible to increased fracture rates at the vertex of the bend. Furthermore, the pockets and other tooth retention mechanisms are relatively complex compared to a typical straightforward cylindrical cutter design. Additionally, because so much of a bent tooth is required to be embedded within the bit body, the number of teeth that may be located in a given area may be limited by the size of the bit body.
Bullet-type drill bit teeth as disclosed in U.S. Pat. No. 5,558,170 issued to Thigpen et al., hereby incorporated herein by reference, are generally cylindrical, with a hemispherical back end for seating in a correspondingly milled pocket. Typically the body of a bullet tooth comprises a hardened material and the face includes a flat circular body coated with a superhard material such as a polycrystalline diamond compact (“PDC”) or tungsten carbide. The corresponding pocket of a bullet-type tooth can include sidewalls extending upwards to partially enclose the top of the tooth to resist prying-out of the tooth. However, such partial enclosure of the top of the tooth may affect tooth clearance and the hemispherical back end may not permit as strong a braze as may be achieved with typical cylindrical cutter designs. Cylindrical designs have a flat back end that is more easily brazed in a corresponding receiving pocket.
In drilling through softer formations, it is advantageous to maximize the depth of cutter penetration. This is achieved by maximizing distribution of the applied drilling load on the cutters, and avoiding distribution of such load to surfaces of the bit that are less capable of efficiently shearing the formation. Accordingly, there exists a need for a cutter design having an increased exposure for greater cutting efficiency, an increased clearance to minimize contact of the formation with the bit body, and with decreased susceptibility to typical cutter failure modes.